In coal-fired power generating plants, as well as in other industrial processes involving combustion of coal, a number of the products of the combustion process include compounds that have an adverse influence on boiler operation, or they are environmentally undesirable and the discharge of which into the environment is subject to environmental regulations. Such compounds include sulfur oxides (SOx), nitrogen oxides (NOx), hydrochloric acid, and such heavy metals as mercury, arsenic, lead, selenium, and cadmium. Additionally, a significant number of nations, including the European Union and Japan, have taken steps to further limit the emissions of carbon dioxide (CO2), and similar steps have been proposed in the United States but are currently being implemented by few of the 50 states.
In order to meet environmental limitations affecting the discharge into the atmosphere of the most prevalent of the most widely regulated compounds, sulfur dioxide (SO2), combustion products from such plants and processes are commonly passed through flue gas desulfurization (FGD) systems. The treatment of flue gases to capture SO2 is often effected in lime- or limestone-based wet scrubbers, in which lime or limestone slurries contact the flue gases before they are discharged into the atmosphere. The sulfur oxides are thereby chemically converted into insoluble calcium compounds in the form of calcium sulfites or sulfates. The sulfur oxides contained in such combustion products are thus converted into less-environmentally-harmful compounds that are either disposed of in landfills, or, when suitably modified or treated, are sold as marketable chemicals as a result of their conversion into marketable gypsum.
Although useful for converting some sulfur oxides, the widely-used types of lime/limestone scrubbers are not very effective in capturing the 1% to 1.5% of the sulfur in the fuel that is transformed during the combustion process into gaseous sulfur trioxide (SO3), which can escape from the scrubber. The SO3 poses operating problems within the boiler itself, in that it leads to corrosion and fouling of low temperature heat exchange surfaces. Additionally, it poses environmental problems in that unless it is captured or transformed, the SO3 results in a persistent, visible plume and the discharge of corrosive and potentially hazardous sulfuric acid mist. Further complicating the matter, selective catalytic reactors (SCR's), which are available and because of high capital costs are installed primarily in the larger, newer such plants to comply with nitrogen oxide emission regulations, essentially cause a doubling of the amount of SO3 that is generated. Consequently the already serious operational and environmental problems caused by the presence of SO3 are magnified.
The SO3 emission problem has been addressed chemically using a variety of alkaline chemicals (wet and dry) that are injected into the system at many different points in the flue gas flow path. Lime or limestone injected into the high temperature region of the boiler can be effective in capturing the SO3, but the commercial materials that are generally utilized tend to magnify boiler deposit problems and increase the quantity of particulates that can escape from the electrostatic precipitators (ESP's). The adverse impact on the precipitators is also encountered when lime or lime hydrate is injected as powders into the lower temperature region downstream of the SCR's. On systems with scrubbers capable of capturing particulates, the precipitator problem can be circumvented by injecting the lime downstream of the precipitator. However, fine powders tend to become agglomerated during the course of handling and result in relatively inefficient SO2 capture, thereby necessitating dosage at several times stoichiometric. Further, the injection of slurries downstream of the ESP pose serious problems relative to drying and deposit buildup in the ducts, because the low temperatures at that point do not provide the evaporative driving force that is needed to quickly flash off the water.
Sodium compounds, such as the bisulfite, carbonate, bicarbonate and carbonate/bicarbonates (Trona) compounds, have also been injected into the cooler regions of the system and are effective in SO3 capture. However, they pose material handling, ash disposal, and potential deposit problems. They also tend to have poor utilization efficiencies unless they are ground to very fine particle sizes. Relatively coarse particles are prone to formation of an outer sulfate shell, thereby inhibiting utilization of the unreacted chemical inside the shell. Additionally, grinding of such materials is expensive, and it creates storage and handling problems because of the fineness and hygroscopic nature of the particles. Ash disposal issues arise because of the solubility of sodium compounds, and in some cases steps to insure containment in the disposal ponds may be required.
Commercially available, but relatively expensive, oil-based magnesium additives can be effective in SO3 capture. In that regard, one of the most effective chemical techniques for controlling both ash-related fouling in the boiler, and also the corrosion and emission problems associated with SO3 generated in solid-fueled boilers, is the injection into the upper region of the boiler of oil slurries of MgO or Mg(OH)2. That technology was originally developed for use with oil-fired boilers in which the magnesium-based oil suspension was usually metered into the fuel. It was later applied to coal-fired boilers. The most widely accepted mode of application of such additives today is by injection of slurries of MgO or Mg(OH)2 into the boiler above the burners and just below the region at which a transition from radiant heat transfer to convective heat transfer occurs.
Another approach to SO3 capture involves the use of so-called “overbased” organic-acid-neutralizing additives of the type that are included in motor oils and as fuel oil combustion additives. Those additives are actually colloidal dispersions of metallic carbonates, usually magnesium or calcium. When burned with the fuel, they are effective at near stoichiometric dosage in capturing SO3 and in mitigating ash deposits caused by vanadium and/or sodium in the oil. The colloids are stabilized by carboxylic or sulphonate compounds and are known to provide mostly particles in the Angstrom range. Though very expensive, the “overbased” compounds are widely used at low dosages to capture vanadium in heavy-oil-fired combustion turbines. Although they have been utilized in SO3 capture efforts, there have been no prior reports of their use for capturing either SO2 or toxic metals.
Although emissions benefits can be obtained by the use of the so-called “overbased” compounds, their much higher cost and combustibility make them a less attractive option for most applications. Additionally, the combustibility of the overbased materials requires hard piping as well as additional safety devices, each of which involves increased costs.
In addition to oil-based slurries, Mg(OH)2 powders and water-based slurries have also been utilized as fireside additives in boilers, but because of their generally coarser particle size they are less efficient in capturing the SO3. Water slurries of MgO have also been injected through specially modified soot blowers installed on oil and Kraft-liquor-fired boilers, in which they moderated high temperature deposits but had only a nominal impact on SO3-related problems because of an inability to apply the chemicals continuously.
In addition to limitations on SOx emissions, regulations aimed at controlling mercury emissions from coal-fired boilers have been promulgated by regulatory authorities, and regulations applicable to other toxic metals are anticipated eventually. A considerable amount of research aimed at finding practical techniques for capturing such toxic metals has shown that high-surface-area solids can capture a significant portion of mercury by adsorption, if the mercury is in an oxidized form rather than in an elemental form. Oxidants, either added to or naturally present in the fuel, such as chlorides, can facilitate the oxidation. Although high-surface-area lime can be effective in mercury capture, the usual commercial products can result in operational problems in the form of ash deposits and increased stack emissions. The most widely accepted way to achieve mercury capture has been the injection of expensive activated carbons in the cooler regions of the boiler gas path.
Combustion systems requiring additional emission control generally fall into two broad groups. The first group includes those systems that are sufficiently large and are sufficiently new to justify the large capital investment in scrubbers for SO2 and in selective catalytic reactors (SCR's) for NOx. The second group includes those systems that are older and smaller, and for which scrubbers and/or SCR's are difficult to physically retrofit and involve a major capital investment that is often difficult in to justify economically.
In the second group of systems, SO2 emission regulations are currently being met by switching to more costly, low-sulfur fuels and/or by utilizing market-based emissions credits. Combustion process modifications have also been used successfully to reduce NOx emissions, but the reduction is often insufficient to bring the systems into compliance with the latest regulations. Those systems may also generate a byproduct fly ash that is higher in unburned carbon as a result of combustion modifications that are aimed at minimizing NOx formation. The efficiency loss as a result of the increased unburned carbon is small, typically less than about 0.5% of the fuel carbon, but if the amount of unburned carbon in the ash is too high (>5% of the ash), the ash becomes unmarketable, thereby converting a potential revenue stream from the sale of ash into an expenditure for ash disposal. Considerable work has gone into optimizing the burners of such systems, but with limited success. Because limiting NOx emissions is an important objective, techniques for separating the carbon from the ash are being pursued as an alternative.
The larger, newer systems can justify the major investment in SCR's, while the smaller, older systems tend to use selective non-catalytic reduction (SNCR), which employs similar reactions to the SCR's using ammonia or an amine, but without the catalysts. Both of those control technologies result in a small amount of ammonia in the flue gas downstream of the SNCR or SCR systems. The ammonia can react with the SO3 that results from the combustion process to form low-melting-point ammonium bisulfate, which can foul air preheaters that are further downstream in the flue gas flow path.
Both groups of combustion systems are likely to be required to conform with additional regulations that require the capture of trace quantities of toxic metals. Despite gas scrubbing, the scrubber/SCR-equipped systems that utilize higher sulfur content fuels also face a new, stack opacity problem that results from a doubling by the SCR's of the SO2 that is catalyzed to SO3 and is emitted as a visible, sulfuric acid mist plume. The acid in the flue gas also results in system operating problems by plugging and corroding lower temperature components of the system.
The sulfuric acid plume problem has resulted in major environmental public relations issues for utilities, as evidenced by American Electric Power Company's purchase of the town of Cheshire, Ohio, because of acid mist discharge issues. The Department of Energy has spent millions of dollars in testing various SO3 control techniques, and a variety of acid-neutralizing systems are being installed. Some systems are currently operated only during the NOx season, that part of the year when NOx controls must be employed (currently May through September). Those SO3 mitigation systems utilize a variety of alkaline chemical compounds that are injected at various points in the flue gas path to effect the acid neutralization. Most of those chemicals, including Ca(OH)2, Mg(OH)2, Trona, and SBS (sodium bisulfite), are relatively coarse in particle size, with the finest-sized particles tested reportedly having a particle size of about 3 microns. However, those chemical compounds are difficult to deploy, they are utilized at rates that are 3 to 12 multiples of stoichiometric, and their use involves significant costs. Although the use of furnace injection of those coarser particles as an emissions control vehicle has been evaluated extensively, most current installations feed chemicals for SO3 control in the cooler section of the system at a point downstream of the SCR's, either as powders, slurries, or solutions.
It is likely that the remaining boiler systems and combustion systems without scrubbers will soon need to meet more stringent SO2 regulations or face early shutdown if a practical, low capital cost, moderate operating cost, pollution control system does not become available. Those same power plants will soon also be required to capture mercury and other toxic metals, as well as to deal with more stringent SOx and year round NOx emission limitations.
Considerable research has been conducted on techniques for capturing the toxic metal pollutants before they can escape from the combustion system and/or damage the SCR catalyst. That research has shown that the injection at various points in the boiler of finely sized, high-porosity, high-surface-area particulate materials, such as specially modified CaO, silicates, MgO, or activated carbon can help to capture most of the metals. Heavy metals (Hg, Se, and As) capture has been shown to be significant when lime is injected into the high temperature region at twice the sulfur stoichiometric ratio, even though the surface area of the injected materials is relatively modest, of the order of about 1 to 4 m2/gm or more, and even though competition exists for that same reagent/reactant surface area by the acid-forming gases. The current regulatory focus is on the capture of mercury, and the current user focus is on injection into the cooler regions of the boiler of expensive, high-surface-activated carbon. However, the adverse operating and environmental impacts of the other toxic metals will eventually lead to emissions regulations for the other toxic metals.
SO2 control utilizing powdered limestone injection into the high temperature furnace, a technology known as LIMB (Limestone Injection Multistage Burner), has been investigated extensively since the 1970's. However, that approach has not been widely implemented because treatment rates twice stoichiometric with −325 mesh powders (typical mean particle size of about 20 microns) captured no more than about 65% of the SO2. That approach also dramatically increases the ash burden (as much as double). And it has posed deposit problems in the boiler convective pass, requiring near continuous operation of the soot blowers, and has overburdened the particulate control device. Much of the research effort has focused on the creation of high-porosity, high-surface-area CaO by flash calcination of the limestone in the furnace. However, the desired improvement in chemical utilization efficiency has not been achieved because of the plugging of the pores of the high-porosity particles with CaSO4, thereby reducing the accessible surface area for reaction and leaving a core of unreacted CaO. Some work with particle sizes in the 5 micron range has been reported, but that approach also has not been utilized commercially because of the pore-plugging problem, along with what is perceived to be a high cost of grinding limestone into a fine particle size.
With regard to SO3 capture, the University of North Dakota Energy and Environmental Research Center recently reported that the tiny fraction, less than about 1.5%, of submicron-size ash particles that are present in fly ash have been found to adsorb SO3. It suggested that the fraction of those particles is important for controlling the SO3 problem. The addition of fine alkaline materials (under 5 microns) was also mentioned. Other workers have reported that fly ash will absorb toxic metals, but its low surface area leads to poor capture efficiency.
Finally, the possibility of modifying combustion conditions to increase the fraction of submicron size particles has not been reported. Instead, the focus has been on adding excessive amounts of what are perceived as fine, ground limestone (−325 mesh) having a median particle size of around 20 microns. The reason for that focus is that limestone is inexpensive, and even if one were to desire smaller particles the normal techniques for providing very fine particle sizes having high-surface-areas have all been judged to be too expensive.
Some research has been conducted on what might be described as a multi-pollutant control process simulating the furnace injection of calcium and magnesium compounds slurried in solutions of nitrogen compounds. Theoretically, the combination would address all the emission issues except CO2. Although the injection of nitrogen solutions to control NOx is in wide use on power boilers, the combination with calcium slurries for simultaneous SO2 capture has not been commercially adopted. Reportedly, the failure to do so is the result of problems with settling and pluggage in the slurry injection systems.
Reducing CO2 emissions has thus far not been the subject of regulations in much of the world. Emphasis has been placed on improving efficiency of fuel use. And research on sequestering the CO2 is ongoing, with some CO2 captured, liquefied, and used in enhancing oil recovery. Most of the commercial SOX emissions control processes for fossil-fueled combustion systems employ limestone (directly or as lime) with the net result being a significant secondary emission of CO2. The scrubbers employing limestone on the larger, newer units are the lowest emitters (about 0.7 ton CO2/ton of SO2 captured) while those using lime have net emissions at least twice as high because of the thermal loss in the calciners. Because the utilization of the limestone is so poor with conventional Furnace Sorbent Injection (FSI), the CO2 released per ton of SO2 captured is nearly 14 tons/per ton.
It is therefore an object of the present invention to provide improved processes by which boiler operational and emissions problems can be reduced more economically than is attainable by presently utilized methods.